1. Field of the Invention
The system and method described here relates generally to transmission power cable monitoring and particularly to the real time optimization of current loads of power cabling systems.
2. Description of Related Art
Several things impact the capacity of a power cable. The capacity is limited by the heating of the line due to factors such as the inherent electrical resistance of the conductor and the current load. If the power cable is overextended (e.g., increase demands on the power cable), the power cable can overheat causing unsafe conditions and potential mechanical breakdown (e.g., sag) that lead to costly repairs. In order to prevent these breakdowns, ampacity calculations are made to determine a maximum temperature that the power cable may endure. Ampacity is the current carrying capacity of a cable.
For a power cable, the size and electrical properties of the electrical conductors, the cable design, and the capacity of the installation to extract cable heat and dissipate it into the surrounding environment determine the ampacity. Cable insulation materials age faster at higher temperatures and the insulating properties often decrease with increasing temperatures. The maximum operating temperature of a cable is limited by the cable design, insulation material, the ambient temperature and thermal conductivity of the medium where the cable is deployed, and desired service life. The cable insulation experiences different temperatures depending on duration and intensity of the current circulating in the conductors and environmental factors. The consequence of excessive operating temperatures is life-reducing damage to the cable and/or permanent insulation break down causing total loss of the cable.
Cable operating temperatures depend on the load “shape” applied (i.e. the intensity of the current and its time variations). Subsequently, cables have different ratings such as steady state, cyclic, transient (emergency) and short-circuit. Transient analyses are typically used to calculate cable thermal ratings under emergency situations. Cable installations also have thermal inertia (it takes time to heat up the cable and its surroundings).
If these “load shapes” and the thermal environment are not taken into account it is difficult to make useful predictions regarding future performance of cable systems. Distributed temperature sensing (DTS) systems provide real-time temperature measurements using optical fibers deployed in or along power cables but do not provide temperature rise/fall predictions based on load shapes.
Therefore determining the maximum current and applied period that the power cable can sustain without thermally induced insulation deterioration allows for more effective and life-prolonging utilization. Ampacity calculations can provide for off-line planning circuit optimization tools. Combined with DTS systems, they can be used in a continuous way to compute the expected operating temperature of cables in an installation and can compute the temperature of the conductor given the fiber temperature. With this information then the complete system can provide off-line planning tools for circuit optimization
Current technologies to monitor the current load and/or perform ampacity calculations often employ mounting a monitoring system to the power cables. These monitoring systems include resistance temperature monitors, current transformers, and more generally, thermocouples and/or solid-state or electromechanical transducers. However, these monitoring systems are often unreliable and unsafe, especially in an extremely high voltage environment. Electrical sensing systems are sensitive to Electro Magnetic Interference (EMI) caused by the electrical and magnetic fields in or around power cables. This EMI disturbance may interrupt, obstruct, or otherwise degrade or limit the effective performance of the electrical sensing systems. Further, if the monitoring system is subjected to electrical fields of a certain magnitude, damage and/or failure of the monitoring system is likely.
These current technologies are severely limited in that they do not provide a spatially continuous or distributed temperature measurement. This is critical because a power cable may have a localized “hot spot” from a heat source in close proximity to the power cable that would be undetected by these approaches.
Examples of heat sources for buried power cables are other power cables crossing the path and generating heat, steam pipes that cross near the cable or in a worst case may even run next to the power cable for some distance, localized manufacturing defects in the power cable (high localized resistance R). Other issues could be varying thermal resistivity in the ground along the length of the power cable or cable duct. Other hot spots could be cable splices where you need to connect two lengths of cable, and these joints are often a concern.
For overhead power cables, the heat source may be sun loading and daily and/or seasonal temperature variations. The cooling effect of wind may impact the temperature and there may be localized pockets where this cooling effect may be very limited and thereby causing hot spots.
Software for ampacity monitoring currently exists but is expensive. In addition software only solutions cannot possibly predict issues such as hot spots. To deal with hot spots, operators often calculate the ampacity for a given cable using expected site conditions such as thermal resistance between cable and environment, expected temperatures and the maximum designed current carrying capacity of the cable. They then de-rate this calculated ampacity value to account for un-expected hot spots and potential inaccuracies in the model. The operators often limit the cable to only carry e.g. 70% of the calculated load.
Knowing the exact location of hot spots by simultaneous use of a distributed temperature measuring system combined with a distributed ampacity model would target these issues and allow the operators to base the circuit (cable) ampacity based on actual hot spot data. This approach would allow the end-user use the cable up to the maximum of the design rating as long as the hot spots are correctly identified and accounted for. Any seasonal variability in temperature and thermal resistance would be accounted for and the system ampacity can be calculated in real time. The combination of forward predictions of ampacity with the real time feedback of actual temperature can enable the system to “self-learn” with real data over time. This could also provide planning optimization tools.
What is needed then is an ampacity monitoring system that uses real time data to take load shapes into account and provides ampacity ratings for static (steady state) and transient (emergency) conditions. For static systems the need is for a system that takes into account cable design, and both cable insulation and cable duct thermal properties to estimate heat generated by resistive losses inside the conductor and how heat is dissipated through the various cable layers. In addition any static model needs to account for the thermal conductivity between the cable and cable duct as well as how various duct materials thermal conductivity impacts the model.
For transient considerations any monitoring system needs to use supplied data to calculate predicted temperatures and to update the thermal conductivity values in the model. The transient model also needs to account for the thermal lag inherent in any cable installation.
Finally there is a need to predict the reliable lifetime of the cable based on the cumulative time at various temperatures. Utilities replace cables today based on how long time the cables have been in operation regardless of the loading the cables experienced during the service life. By continuously measuring the cable temperature, cumulative aging of cable insulation can be calculated. This will allow the utilities to replace the cables most likely to fail based on actual insulation aging data rather than replacing them on service life alone. This may represent significant improvements in circuit and system reliability with significant cost savings as only cables at risk will be replaced and the service life of the remaining cables will be extended.
An electrical power transmission network typically comprises an electrical power generation source that is connected to an electrical power distribution network by overhead electrically conductive cables suspended between spaced-apart towers that are installed along electric utility right-of-ways. These electrically conductive cables are susceptible to lightning strikes because of the conductive characteristic of the cabling and the height of the support towers. Cables called “ground wires” are typically suspended between the spaced-apart support towers and above the base electrical conductors of the power transmission network to protect from the high current surges presented by direct or nearby lightning strikes. These ground wires, also called shield wires or earth wires, provide a path for the high current transients generated by lightning strikes within the proximity of the ground wire to safely discharge via the ground wire, the local support towers, and the ground.
The electric utility right-of-ways for overhead electrical power transmission lines often provide an attractive path for the installation of overhead telecommunication cables. Because the communications content of light signals carried by optical fibers are not affected by the high voltage and current environment typically found within an electrical power transmission network, ground wire cables are often combined with an optical fiber or, more often, a bundle of optical fibers, to efficiently provide light wave communications via the existing overhead transmission network, More specifically, a bundle of optical fibers are typically mounted within an electrical conductor to form a ground wire cable that is installed between spaced-apart support towers and above the electrical transmission lines. In this manner, the ground wire cable functions as both a ground wire and a telecommunications cable and thereby enables the existing electric utility right-of-way to be used for telecommunications. These combined systems are sometimes referred to as optical fiber composite overhead ground wires and the acronym OPGW is often used. The contained optical fibers are actually insulators and help protect against power transmission line and lightning induction, external noise, and cross-talk. Typically OPGW cables contain single-mode optical fibers because of the low transmission loss, allowing long distance transmission. These fibers are routed to instrument rooms at suitable distances where they may be connected to optical amplifiers/repeaters for optical communication.
A power utility company often installs many more fibers than it needs for internal communications both to allow for future needs and also to lease or sell to communications companies. Rental fees for these spare fibers can provide a valuable resource of revenue for the electrical utility. These spare fibers represent one potential embodiment of the disclosed new system and method described in this application. The use of the already deployed optical fibers within OPGW cables could allow a practical and affordable system that does not require the investment and deployment in optical fibers embedded in power cables. In addition use of OPGW cables addresses many questions related to installation safety and long-term reliability of an optical fiber monitoring system.
The previously mentioned needs for an ampacity monitoring system for power cables that uses real time data to take load shapes into account and provides ampacity ratings for static (steady state) and transient (emergency) conditions could thus be implemented without the major investment of resources in the deployment of new optical fiber by a system to be described herein in conjunction with the use of spare optical fibers contained in OPGW cables.